1. Field of the Invention
The present invention relates to methods for characterizing petroleum fluids extracted from a hydrocarbon-bearing geological formation. The invention has application to reservoir architecture understanding, although it is not limited thereto.
2. Description of Related Art
Petroleum consists of a complex mixture of hydrocarbons of various molecular weights, plus other organic compounds. The exact molecular composition of petroleum varies widely from formation to formation. The proportion of hydrocarbons in the mixture is highly variable and ranges from as much as 97 percent by weight in the lighter oils to as little as 50 percent in the heavier oils and bitumens. The hydrocarbons in petroleum are mostly alkanes (linear or branched), cycloalkanes, aromatic hydrocarbons, or more complicated chemicals like asphaltenes. The other organic compounds in petroleum typically contain carbon dioxide (CO2), nitrogen, oxygen, and sulfur, and trace amounts of metals such as iron, nickel, copper, and vanadium.
Petroleum is usually characterized by SARA fractionation where asphaltenes are removed by precipitation with a paraffinic solvent and the deasphalted oil separated into saturates, aromatics, and resins by chromatographic separation.
Saturates include alkanes and cycloalkanes. The alkanes, also known as paraffins, are saturated hydrocarbons with straight or branched chains which contain only carbon and hydrogen and have the general formula CnH2n+2. They generally have from 5 to 40 carbon atoms per molecule, although trace amounts of shorter or longer molecules may be present in the mixture. The alkanes include methane (CH4), ethane (C2H6), propane (C3H8), i-butane (iC4H10), n-butane (nC4H10), i-pentane (iC5H12), n-pentane (nC5H12), hexane (C6H14), heptane (C7H16), octane (C8H18), nonane (C9H20), decane (C10H22), hendecane (C11H24)—also referred to as endecane or undecane, dodecane (C12H26), tridecane (C13H28), tetradecane (C14H30), pentadecane (C15H32) and hexadecane (C16H34). The cycloalkanes, also known as napthenes, are saturated hydrocarbons which have one or more carbon rings to which hydrogen atoms are attached according to the formula CnH2n. Cycloalkanes have similar properties to alkanes but have higher boiling points. The cycloalkanes include cyclopropane (C3H6), cyclobutane (C4H8), cyclopentane (C5H10), cyclohexane (C6H12), and cycloheptane (C7H14).
The aromatic hydrocarbons are unsaturated hydrocarbons which have one or more planar six-carbon rings called benzene rings, to which hydrogen atoms are attached with the formula CnHn. They tend to burn with a sooty flame, and many have a sweet aroma. The aromatic hydrocarbons include benzene (C6H6) and derivatives of benzene, as well as polyaromatic hydrocarbons.
Resins are the most polar and aromatic species present in the deasphalted oil and, it has been suggested, contribute to the enhanced solubility of asphaltenes in crude oil by solvating the polar and aromatic portions of the asphaltenic molecules and aggregates.
Asphaltenes are insoluble in n-alkanes (such as n-pentane or n-heptane) and soluble in toluene. The C:H ratio is approximately 1:1.2, depending on the asphaltene source. Unlike most hydrocarbon constituents, asphaltenes typically contain a few percent of other atoms (called heteroatoms), such as sulfur, nitrogen, oxygen, vanadium, and nickel. Heavy oils and tar sands contain much higher proportions of asphaltenes than do medium-API oils or light oils. Condensates are virtually devoid of asphaltenes. As far as asphaltene structure is concerned, experts agree that some of the carbon and hydrogen atoms are bound in ring-like, aromatic groups, which also contain the heteroatoms Alkane chains and cyclic alkanes contain the rest of the carbon and hydrogen atoms and are linked to the ring groups. Within this framework, asphaltenes exhibit a range of molecular weight and composition. Asphaltenes have been shown to have a distribution of molecular weight in the range of 300 to 1400 g/mol with an average of about 750 g/mol. This is compatible with a molecule contained seven or eight fused aromatic rings, and the range accommodates molecules with four to ten rings. It is also known that asphaltene molecules aggregate to form nanoaggregates and clusters.
Reservoir compartmentalization can be a significant impediment to efficient reservoir development. Reservoir compartmentalization is the natural occurrence of hydraulically isolated pockets within a reservoir. In order to produce a reservoir in an efficient manner, it is necessary to know the structure of the rock and the level of compartmentalization. A reservoir compartment does not produce unless it is tapped by a well. In order to justify the drilling of a well, the reservoir compartment must be sufficiently large to sustain economic production. Furthermore, in order to achieve efficient recovery, it is generally desirable to know the locations of as many of the reservoir compartments as practical before extensive development has been done.
There are three industry standard procedures widely used to understand reservoir compartmentalization. First is the evaluation of petrophysical logs. Petrophysical logs may identify impermeable barriers, and the existence of such barriers can be taken to mean that the reservoir is compartmentalized. Examples include gamma ray and NMR logs, both of which can identify impermeable barriers in favorable situations. Another example is the evaluation of mud filtrate invasion monitored by resistivity logs. However, impermeable barriers may be so thin that they are not observable by these logs, or barriers observed by these logs may not extend away from the wellbore and therefore may not compartmentalize the reservoir. Second is the evaluation of pressure gradients. If two permeable zones are not in pressure communication, they are not in flow communication. However, the presumption that pressure communication implies flow communication has been repeatedly proven to be incorrect. Pressure equilibration requires relatively little fluid flow and can occur more than five times faster than fluid compositional equilibration, even in the presence of flow barriers. Continuous pressure gradients are a necessary but insufficient test for reservoir connectivity. Third is the comparison of geochemical fingerprints of fluid samples acquired from different locations in the reservoir. Petroleum is a complex chemical mixture, containing many different chemical compounds; the composition of that petroleum can therefore be treated as a fingerprint. If the composition of petroleum samples from two different places in the reservoir is the same, it is assumed that fluids can flow readily between those two places in the reservoir, and hence that the reservoir is connected. However, forces such as biodegradation and water washing can occur to different extents in different parts of the reservoir, causing two locations in the reservoir to have different fingerprints even if they are connected. Additionally, petroleum samples generated from the same source rock may have very similar fingerprints even if they come from locations in the reservoir that are presently disconnected.
An alternative method to assess connectivity is to evaluate hydrocarbon fluid compositional grading. The chemical composition of petroleum must be different in different parts of a connected reservoir. This change in composition with position (typically depth) in the reservoir is referred to as compositional grading. The magnitude of this compositional grading (i.e., the difference in the composition of two fluids collected from different depths), in connected reservoirs at thermodynamic equilibrium, can be measured with downhole fluid analysis and predicted with a mathematical equation of state (EOS) model. The EOS model is based on assumptions that the reservoir is connected and at thermodynamic equilibrium. If the magnitude of compositional grading as measured matches the predicted composition grading, then the assumptions of the EOS model are confirmed. In the event that the magnitude of the measured compositional grading does not match the predictions of the EOS model, it can be assumed that there is reservoir compartmentalization or that the reservoir fluids are not in equilibrium. Many different forces can contribute to a lack of thermodynamic equilibrium, such as tar mats, water washing, biodegradation, and real-time charging. It can be difficult to determine whether the reservoir is compartmentalized or in a state of thermodynamic non-equilibrium, and this determination can be critical to important development decisions.
More specifically, there is an increasing awareness that fluids are often heterogeneous in the reservoir and that reservoir fluids frequently demonstrate complicated fluid compositions, properties, and phase behaviors in single oil columns due to a variety of factors including gravity, thermal gradients, biodegradation, active charging, water washing, and phase transitions. Most of these mechanisms result in non-equilibrium or non-stationary state conditions acting on reservoir fluids and, often, these non-equilibrium factors dominate over diffusive and convective processes that can drive the fluids towards equilibrium. In these scenarios, the current modeling methods can be inaccurate and offer limited insight into the real compositional properties of the reservoir fluids. These limitations make it difficult to determine whether the reservoir is compartmentalized or connected, but in a state of non-equilibrium.
Thus, there is a clear need for methodologies that provide for an effective understanding of reservoir fluids, particularly for scenarios where it is difficult to determine whether the reservoir is compartmentalized, or connected but in a state of non-equilibrium.